Liquid buildup can occur in aging production wells and can reduce the well's productivity. To handle the buildup, operators may use beam lift pumps or other remedial techniques, such as venting or “blowing down” the well to atmospheric pressure. These common techniques can cause gas loss. Moreover, blowing down a well can produce undesirable methane emissions. In contrast to these techniques, operators can use a plunger lift system, which reduces gas losses and improves well productivity.
A prior art plunger lift system 100 as illustrated in FIG. 1A has a plunger 110 and a bottom hole bumper 120 positioned in tubing 14 within well casing 12. At the wellhead 10, the system 100 has a lubricator/catcher 130 and controller 140. In operation, the plunger 110 initially rests on the bottomhole bumper 120 at the base of the well. As gas is produced to a sales line 150, liquids may accumulate in the wellbore, creating back-pressure that can slow gas production through the sales line 150. Using sensors, the controller 140 operates a valve at the wellhead 10 to regulate the buildup of gas in the casing 12.
Sensing the slowing gas production, the controller 140 shuts-in the well at the wellhead 10 to increase pressure in the well as a high-pressure gas accumulates in the annulus between the casing 12 and tubing 14. When a sufficient volume of gas and pressure are reached, the gas pushes the plunger 110 and the liquid load above it to the surface so that the plunger 110 essentially acts as a piston between liquid and gas in the tubing 14. As shown in FIG. 1B, the plunger 110 can have a solid or semi-hollow body, and the plunger 110 can have spirals, fixed brushes, or pads on the outside of the body for engaging the tubing 14.
Eventually, the gas pressure buildup pushes the plunger 110 upward to the lubricator/catcher 130 at the wellhead 10. The column of fluid above the moving plunger 110 likewise moves up the tubing 14 to the wellhead 10 so that the liquid load can be removed from the well. As the plunger 110 rises, for example, the controller 140 allows gas and accumulated liquids above the plunger 110 to flow through upper and lower outlets 152 and 154. The lubricator/catcher 130 captures the plunger 110 when it arrives at the surface, and the gas that lifted the plunger 110 flows through the lower outlet 154 to the sales line 150. Once the gas flow stabilizes, the controller 140 shuts-in the well and releases the plunger 110, which drops back downhole to the bumper 120. Ultimately, the cycle repeats itself.
To ensure that a well is not able to flow uncontrolled, some wellbores require a downhole safety valve 20 that closes when flow and pressure exceed acceptable limits or when damage occurs to the surface equipment in an emergency. Some safety valves installed in production tubing 14 are tubing retrievable, while other safety valves are wireline retrievable. The downhole safety valves, such as flapper valves, can prevent blow-outs caused by an excessive increase of flow through the wellbore or wellhead damage. Because the plunger 110 travels along the tubing 14 between the bumper 120 at the base of the wellbore and the catcher 130 at the surface, the plunger 110 must travel through the safety valve 20. As expected, the plunger 110 must be designed to fit through the decreased passage within the safety valve 20 and not damage or interfere with the safety valve's operation.